Providing voltage to customers within a proper range is one of the electric utility's fundamental tasks. VVC utilizes load/generation forecast, load allocation, a system network model, network topology, market information on energy trades, available real-time measurements/information, etc., to compute and control the desirable settings of system devices that contribute towards voltage profile and reactive power. These volt/VAR devices include voltage regulators, load tap changers, primary and secondary capacitor banks, distribution flexible AC transmission systems (DFACTS), unified power flow controls (UPFC), energy storage systems (ESS), and smart inverters with real and reactive power controls. Optimal settings are sent to the local controllers of VVC elements to be implemented in order to accomplish a set of desired objectives and satisfy a set of defined practical constraints, which are described as follows.
A basic requirement of VVC is to maintain the voltage profile at all load nodes within the acceptable limits under all loading conditions, as defined by standards such as ANSI. ANSI C84.1 standard outlines three voltage levels: low voltage LV (1 kV or less), medium voltage MV (greater than 1 kV and less than 100 kV), and high voltage HV (greater than or equal to 100 kV). Within each voltage level, two ranges of voltage are defined, Range A and Range B, discussed below.
Utilities are usually mandated to design and operate their system such that the service voltage is within a standard range. This is defined as Range A, and is utilized for normal operating conditions. A second range, Range B, is used for abnormal operating conditions. Range B is a relaxed limit that depends on extent, frequency, and duration. However, when the electrical system experiences voltage conditions in this range, corrective actions must commence within a reasonable time to bring voltage level back within Range A. For low voltage level in distribution systems, ANSI C84.1 provides boundary limits of −5% and +5% for Range A and −8.3% and +5.8% for Range B. However, in medium voltage level, ANSI C84.1 provides boundary limits of −2.5 to +5% for Range A, and −5 to +5.8% for Range B.
Another objective of VVC is improving system efficiency and minimizing losses through voltage optimization.
A further objective of VVC is reducing electrical demand through conservation voltage reduction (CVR).
Other objectives of VVC are: power factor correction, enabling high penetration of distributed generation (DG) and renewable resources, enabling islanded microgrids, satisfying distribution feeder capacity limits, and satisfying limits on VVC device operations due to limit of their energy capacity, life expectancy, and maintenance costs.
Modern electric power systems (EPS) are faced with a high degree of complexity and uncertainty due rising factors such as aging and constrained infrastructure, penetration of distributed generation (DG), new loads (e.g. electric vehicles (EVs)), and rise of energy storage devices. These factors may cause uncertain voltage profiling on feeders. As a result, conventional VVC strategies are becoming inadequate to satisfy the voltage regulation and optimal system performance in terms of real-time adaptability with dynamic system operating conditions and topologies.
Electrical power systems are furthermore hierarchical structures with generation and bulk power operations at the top, a transmission system as the next tier, a distribution system as the next, etc. Furthermore, large distribution systems may include microgrids and non-microgrid branches. A microgrid typically includes localized groupings of loads, generation sources, and storage devices that are connected to a traditional centralized grid, or macrogrid.
Centralized control approaches for these large systems can be prohibitively complex and cumbersome to perform wide area-optimized control. Such systems tend to apply centralized control approaches based on simple one-way communications to devices and heuristic rules, and not coordinated amongst all tiers of the EPS. Alternatively, local control approaches will be far from optimal because there is no explicit centralized coordination among different controllers/devices at the system level. From another perspective, VVC is but one application of an EPMAS. The infrastructure and resources required for implementing VVC should be leveraged to provide other functionalities, such as microgrid controls, optimal feeder configurations, and distributed energy resource (DER) management.
Optimizing an EPS across tiers and EPMAS functionalities can be a formidable task, particularly when network conditions change. Traditionally, volt/VAR devices such as voltage regulators and switched capacitor banks are operated as independent devices, with no direct coordination between the individual controllers. Such an approach might be effective for maintaining acceptable voltage and reactive power flow near the controllers, but typically does not produce optimal results for the entire system.
Distribution feeders typically work in radial or open loop topologies. Therefore, distribution systems may experience issues with undervoltage due to high loading on their longer feeders. Appropriate voltage regulation has great importance for improving voltage profile, reducing system losses, and increasing system efficiency.
Conventional distribution systems and their control strategies such as protection coordination, volt/VAR control (VVC), and fault detection, have been designed based on unidirectional power flow, i.e., the substation is the only source of power. However, the insertion of DG units into distribution systems renders this assumption invalid. As a result, several challenges related to system operations such as voltage profile, protection coordination, voltage flicker due to variable output power from renewable resources; reverse power flow, fault detection, and service restoration have been raised.
Four control devices are typically used to control voltage and reactive power flow in distribution systems: Load Tap Changer (LTC), Substation Capacitor (SC), Step Voltage Regulator (SVR) and Feeder Switched Capacitor (FSC).
FIG. 1 illustrates the four typical volt/VAR control devices in distribution systems. In FIG. 1, 101 indicates a Distribution system substation and 102 indicates a load tap changer (LTC) which is connected at the main substation transformer to keep the secondary voltage close to a specified value at different loading conditions. 103 indicates a medium voltage (MV) busbar. 104 indicates a MV to low voltage (LV) transformer. 105 indicates distribution system load points. 106 indicates a substation capacitor (SC) which connects to the secondary bus of the substation to regulate the reactive power flow through the main transformer in order to keep the system operating at acceptable power factor (pf). 107 indicates a feeder switched capacitor (FSC) which connects at different locations on feeders, to provide voltage regulation and reactive power compensation in order to improve the voltage profile along the feeder. 108 indicates a step voltage regulator (SVR) which connects at different locations on feeders, to provide voltage regulation to improve the voltage profile along the feeder.
Previously, the VVC could be implemented using different approaches, such as local VVC, remote VVC, and Distribution-model-based VVC. Each of these approaches is discussed in more detail below.
Local VVC
Local, or standalone, VVC is based on locally available information. Control set-point adjustments for VVC devices are very infrequent and can be implemented on a seasonal basis. In local VVC, each device receives local information from the system, and then through local decision processes selects a control action to implement.
Usually, the LTC and voltage regulators are controlled with line drop compensation (LDC). LDC estimates the line voltage drop (ΔV) and performs voltage corrections based on feeder current (Icomp), voltage (Vreg), and system equivalent parameters (Rset, Xset).
On the other hand, capacitor banks can be controlled by different modes of local controls, such as the following:                a. Power factor: closes the capacitor bank when the lagging power factor is less than a defined threshold, and begins timing to open the capacitor bank when the leading power factor is less than a defined threshold. In general, power factor control is not recommended. This is because if the power factor at light load is low, this would not be an appropriate time to switch a shunt capacitor in. Also, if the power factor during heavy load is high and the capacitor bank does not operate, the potential benefit of the capacitor bank will not be realized.        b. Current: closes the capacitor bank when the phase current is greater than the high current threshold and begins timing to open the capacitor bank when the phase current is less than the low-current threshold. Current control works well if the power factor of the load is fairly constant.        c. Voltage: closes the capacitor bank when the bus voltage is outside of the thresholds and begins timing to open the capacitor bank when the bus voltage greater than a defined voltage inhibit threshold. Voltage controlled FSC are most appropriate when the main role of capacitors is voltage regulation.        d. Reactive power: energize capacitors banks when lagging kVAR reactive power flow exceeds a set-point, and de-energize when leading kVAR reactive power flow exceeds high leading kVAR threshold. To minimize the reactive power flow, reactive power controlled capacitors are most appropriate.        e. Time-based: configure the time of day to close and open the capacitor bank. Thus, shunt capacitors are switched in and out at a pre-determined time of day. This type of control can be applied if the load characteristics are predictable and consistent over long periods of time. However, this control strategy can become inefficient when the load profile changes daily or seasonally or if variable distributed generation is involved.        f. Temperature: has a similar characteristic to time control except that capacitor bank switching is triggered by ambient temperature. This control type is suitable where loading has a strong correlation with temperature.        
The strengths and weaknesses of local VVC can be summarized as follows. The strengths are that it provides a low-cost, modular self-contained system requiring minimal operator involvement and does not rely on field communications. The weaknesses are that it lacks coordination among volt/VAR devices, with potential conflicting controls and operations; system operation may not be optimal under different conditions; it lacks visibility beyond local conditions; it lacks flexibility and adaptability to respond to changing conditions such as load and generation levels; it does not handle high penetrations of distributed generation (DG) effectively; and it typically cannot override its set operation during emergencies.
Remote VVC
In remote control, VVC devices are monitored and controlled by the utility's Supervisory Control and Data Acquisition (SCADA) system. Local LTC and SVR controllers change their tapping and SC and FSC controllers open and close their switches based only on commands from the SCADA system. Control decisions are based on predefined system rules or heuristics. An adjustable SCADA heartbeat time ensures that communications remain active. The operation of these systems is primarily based on a stored set of predetermined rules.
Remote VVC is typically handled by two independent processes, VAR dispatch and volt control. VAR dispatch controls capacitor banks to improve power factor and reduce electrical losses. Volt Control controls LTCs and/or SVRs to keep consumer voltage magnitudes within standards.
The strengths and weaknesses of remote VVC can be summarized as follows. Its strengths are that it provides remote measurements with predetermined rules; operations can be overridden during emergencies; it has better scalability and coordination over local (standalone) control; and it has potential efficiency improvements over local control. Its weaknesses are that it is typically more expensive and has greater complexity with communication infrastructure; operation of VAR and volt devices are usually not coordinated (separate rules for VAR dispatch and volt Control); system operation may not be optimal under different conditions; it lacks flexibility and adaptability to respond to changing conditions such as load and generation levels (rules are fixed in advance); it cannot handle high penetrations of DG effectively; and it typically requires greater operator involvement and training.
Distribution Model-Based VVC
This control scheme aims to achieve better performance by utilizing the “as operated” distribution engineering model to solve the problem of volt/VAR as an optimization problem. This is typically run for 24 hours of the day before the dispatch day (“day-ahead planning”) utilizing day-ahead load/generation forecast. Therefore, it develops and executes a coordinated optimal operating schedule for all VVC devices to achieve utility-specified objectives. The LTC, SVR, SC and FSC are remotely dispatched every hour, by using an automated schedule, which is defined based on day-ahead load/generation forecast.
An objective of the volt/VAR optimization problem is to minimize system losses, while keeping consumer voltage magnitudes within standards and limiting the number of LTC, SVR and capacitor banks switching operations. Solving this optimization problem is not a trivial task because of the load variation, the discrete nature of the LTC, SVR and capacitor bank switching and nonlinear power flow equations.
The strengths and weaknesses of distribution model based VVC can be summarized as follows. The strengths are that it provides a coordinated system of VVC devices; it can provide an optimal solution based on day-ahead load forecasting; it provides flexible operating objectives accommodating various needs; it is able to handle complex feeder arrangements; it can model the effects of DG and other modern grid elements such as active inverter controls and electric vehicles; it is highly scalable; and the system can assist the operator with training and automated operations. Its weaknesses are that its complexity leads to a lack of field proven products except in centralized distribution management systems; it has a higher cost to implement, operate and sustain; due to load variations, while VVC settings are optimum during their dispatching times, there is no guarantee that they will continue to be optimal until the next scheduled dispatch; it does not typically have the capability to adapt automatically to load changes that deviate from forecast.
Inappropriate voltage regulation can cause many problems for customers. These include unsafe and inefficient operation of electronic devices, tripping of sensitive loads, overheating of induction motors (IMs), and equipment failures that lead to higher no-load losses in transformers. Additionally, inappropriate control of reactive power flow can increase the total system losses.
For example, the continuous increase of renewable DG penetration changes the characteristics of distribution systems from being passive with unidirectional power flow to active with bidirectional power flow. These DGs are usually not utility owned and are intermittent energy sources such as wind and solar based DG units. When DGs are connected to a distribution system, they alter the voltage profile and interfere with the conventional VVC strategies of LTCB, SVRs and capacitor banks. Consequently, overvoltage, undervoltage, increased system losses and excessive wear and tear of VVC devices may occur. In addition, load variations are becoming more adverse, with EVs on the rise and changes in usage by end-use customers through demand response programs. High R/X ratio for distribution lines limits the voltage correcting abilities of VAR-only devices.